Subsea production system

ABSTRACT

Methods and arrangements for production of petroleum products from a subsea well. The methods comprise control of a downhole separator, supplying power fluid to a downhole turbine/pump hydraulic converter, performing pigging of a subsea manifold, providing gas lift and performing three phase downhole separation. Arrangement for performing the methods are also described.

[0001] The present invention relates to a method of controlling adownhole separator according to the preamble of claim 1, a method ofsupplying power fluid to a downhole turbine/pump hydraulic converteraccording to the preamble of claim 3, a subsea petroleum productiondevice according to the preamble of claim 9, a method for performingpigging of a subsea manifold and flowline according to the preamble ofclaim 28, a subsea petroleum production arrangement according to thepreamble of claim 31 and an arrangement for controlling a downholeseparator according to claim 35.

[0002] One of the largest cost savings potential in the offshore oil andnatural gas production industry is the zero topside facilities concept.i.e. to place as much of the equipment used for producing hydrocarbonson the seabed or downhole. Ideally this would mean the direct transportof produced hydrocarbons from subsea fields to already existing offshoreplatforms or all the way to shore. To achieve this, several of thetopside processes and the provision of various power supplies have to bemoved subsea or downhole. This preferably includes separation tointermediately stabilized crude, provide dry gas and most importantremove water to reduce pipeline transportation cost and reduce hydrateformation problems associated with long distance hydrocarbon transport.Further advantages may be achieved by utilising subsea single phase ormultiphase pump, gas compressor and gas liquid separation.

[0003] To achieve the above, electric and hydraulic power has to besupplied from platform or shore and distributed to the various subseaconsumers. Hydraulic power has to be made available locally at thesubsea production unit to serve equipment at the seabed or downhole.

[0004] Water is almost always present in the rock formation wherehydrocarbons are found. The reservoir will normally produce anincreasing portion of water with increase time. Water generates severalproblems for the oil and gas production process. It influence thespecific gravity of the crude flow by dead weight. It transports theelements that generate scaling in the flow path. It forms the basis forhydrate formation, and it increases the capacity requirements forflowlines and topside separation units. Hence, if water could be removedfrom the well flow even before it reaches the wellhead, several problemscan be avoided. Furthermore, oil and gas production can be enhanced andoil accumulation can be increased since increased lift can be obtainedwith removal of the produced water fraction.

[0005] A downhole hydrocyclone based separation system can be appliedfor both vertically and horizontally drilled wells, and may be installedin any position. Use of liquid-liquid (oil-water) cyclone separation isonly appropriate with higher water-cuts (typical with water continuouswellfluid). Water suitable for re-injection to the reservoir can beprovided by such a system. Cyclones are associated with purifying onephase only, which will be the water-phase in a downhole application.Using a multistage separation cyclone separation system, such asdescribed in pending Norwegian patent application NO 2000 0816 of thesame applicant will reduce water entrainment in the oil phase. However,pure oil will normally not be achieved by use of cyclones. Furthermore,energy is taken from the well fluid and is consumed for setting up acentrifugal field within the cyclones, thereby creating a pressure drop.

[0006] A downhole gravity separator is associated with a well speciallydesigned for its application. A horizontal or a slightly deviatedsection of the well will provide sufficient retention time and astratified flow regime, required for oil and water to separate due todensity difference.

[0007] The separated formation water can be directed up through thewellhead, but would be best disposed of by directly re-injecting it intoa reservoir below the oil and/or gas layers, to stabilize and uphold thereservoir pressure in the oil formations. Until recently this has beendone by injecting the water in a separate wellbore several kilometresaway from the hydrocarbon producing well. However, since an increasingnumber of wells now are highly deviated and extending through arelatively thin oil and/or gas producing formation, the water may beinjected in the same well, some distance from the oil and/or gasproducing zone.

[0008] Both the cyclone type and the gravity downhole hydrocarbonseparator can be combined with either Electrical Submersible Pumps(ESP's) or Hydraulic Submersible Pumps (HSP's). The use of ESP's haveincreased drastically over the last years, initially for shore basedwells, then on offshore platform wells and finally over the last fewyears on subsea wells. The ESP's are primarily used for pressureboosting the well fluid, but is also applied with cyclone separators forre-injecting produced water and boosting the separated oil to thesurface. The pump is driven by asynchrone alternating current utilizingvariable frequency, drive provides a variable speed motor driving thepump. Hence, a variable pressure increase can be provided to the flow.This technology is currently improving and is applied in anever-increasing amount of problem wells. The pump motors requireselectric power to be provided from the platform to which the subseasystem is connected, or from onshore. One ore more subsea cables areneeded as well as a set of subsea, mateable high voltage electricconnectors, depending on the number of pumps. Special arrangements haveto be made to penetrate the wellhead, and the downhole cable has to beclamped to the production tubing during the well completion. The pump isinstalled as part of the tubing and hung off the tubing hanger in thex-mas tree. Pump installed by coiled tubing is also being introduced.Limited operational time of a downhole ESP is largely caused by failurein power cable, electrical connections and electrical motors.

[0009] The HSP is rotational equipment consisting of a hydraulic poweredturbine mechanically driving a pump unit. It is compact and may transfermore power compared to what is currently available with use of ESP's.The rotational speed is very high, resulting in fewer stages and a morecompact unit then typical for ESP. Even though the higher rotationalspeed makes the bearings more sensitive to solid particles. Use of moreabrasive resistance materials counteracts this problem. The applicationof hydrostatic bearings and continuous lubricated bearings with cleanfluid supplied from surface gives a hydraulic driven downhole pumpextended time in operation in a downhole environment, compared with whatis currently expected of an ESP. The HSP's may be installed in the wellon the tubing, by coiled tubing or by wireline operation. The pump canbe driven by a conventional hydraulic motor but more likely by aturbine.

[0010] A gas reservoir normally produced a dry gas into the well inflowzone. When reservoir pressure has depleted or when well draw-down ishigh condensate may be formed. Water may be drawn from pockets in thereservoir formation of from a gas-water interface in the formation. Theenergy required for lifting produced liquid to the seabed will result ina substantial pressure drop in the production tubing. Removing the water(and/or condensate) downhole for local injection may thus either be ofbenefit by achieving a higher production rate determined by a resultinglower wellbore flowing pressure. Alternatively, a lower production ratecan provide higher wellhead pressure which can help increasing thepossible tie-back distance of a subsea field development to an existinginfrastructure.

[0011] When considerable volume of gas is present in the wellbore aoil-water separator will have reduced capacity and separationperformance will decline. In this case an downhole gas-liquid separatorcan be built-in upstream the oil-water. A gravity separator may be used,but will be ineffective when liquid is in form of mist carried with thehigh velocity gas flow. A centrifugal type separator will have enhanceperformance and enable acceleration of the gas phase past the oil-waterseparator thereby minimizing flow area occupied by gas.

[0012] Certain reservoir conditions and infrastructures may require flowassistance to enable production of oil and gas, and transportation fromthe reservoir to a production facility, economically, over the life of afield and in the environment. Generally reservoir pressure, high crudespecific gravity, high viscosity, deep water, deep reservoir, longtie-back distance and high water content could put different demands andrequirements on the equipment used subsea. These demands andrequirements may very often vary over time.

[0013] Gas lift is a well-known method to assist the flow. As gas isinjected in the flow some distance below the wellhead the commingled gasand crude specific gravity is reduced, thus lowering the wellbore inflowpressure resulting in an increased inflow rate. As pressure is reducedhigher up in the production tubing, further increasing the gas volume,the gravity is even more reduced, helping the flow considerably. The gasis normally injected inthe annulus through a pressure controlled inletvalve into the production tubing at a suitable elevation.

[0014] Another method to increase lift is by introducing a downholepump, electrical or hydraulic powered, to boost the pressure in theproduction tubing. The pump should preferably be positioned at thebottom of the well where gas has not been released form the oil, thusproviding better efficiency and preventing cavitation problems.

[0015] Using gas for gaining artificial lift will increase frictionalpressure drop since total volume flow increases with gas being broughtback to host. At long tie-back distances the net effect of using gaslift becomes low when gain in static pressure is reduced by increaseddynamical pressure losses. However, downhole gas lift can beaccomplished locally at the production area by separating andcompressing a suitable rate of gas taken from the wellfluid anddistributing to the subsea wells for injection. This re-cycling of gasreduces the amount of gas flowing in the pipeline compared to having gassupplied from the host. The advantage of this can be utilized byincreasing production rate from the wells, reducing pipeline size orincreasing capacity by having additional well producing via thepipeline. In addition to this gas life at the riserbase will become moreeffective with this process configuration.

[0016] A cluster type subsea production system is typically comprisingindividual satellite trees arrayed around and connected to a centralmanifold by individual flowline jumpers. A template subsea productionsystem consists of a compact (closely arrayed), modular, and integrateddrilling and production system, designed for heavy lift vessel ormoonpool/drilling rig deployment/recovery with capability for early-welldrilling, ultimately leading to early production. The system isgenerally associated with a four-well scenario, although largertemplates of 6 or 8 slots are sometimes considered, depending on theoverall system requirements. In most cases the template will be equippedwith a production manifold consisting of two production headers and apipe spool connecting the headers at one end. This will allow for roundtrip pigging operations. In case of only one production header is used,pigging operations will require a subsea pig launcher and/or a subseapig receiver.

[0017] The main function of the manifold is to commingle the productioninto one or more flowlines connected to a topside production facility,which may be located directly above or several kilometers away from themanifold. The manifold is usually a discrete structure, which may bedrilling-vessel deployed or heavy-lift vessel deployed, depending onsize and weight.

[0018] The production branches are tied off from the production headerto the manifold import hub via a system of valves, allowing productionflow to be directed into one of the production headers, or an individualtree to be isolated from the header. Alternatively, all production maybe routed to one flowline allowing for the other flowline to be utilizedfor service operations.

[0019] In some cases the production branches also include chokes. Thisis depending upon the control system philosophy. Typically, the manifoldwill include a manifold control module. The main purpose of this is tomonitor pressure and temperature and control manifold valves. Otherfunctions may also be included, such as pig detection, multiphaseflowmeter interface, sand detection and valve position indication.

[0020] An alternative is also to include the tree control modules in themanifold. This may eliminate the need for a dedicated manifold controlmodule, as the tree control modules can control and monitor manifoldfunctions. Again this is dependent on the overall control philosophy,number of functions, and the step-out distance.

[0021] Removing water from the well fluid late in the production liftwhen reservoir pressure has declined and water content has increasedfacilitates a lessening of fluid transport pipeline capacity. Electricalpower is normally supplied to the subsea pumps via individual cables.Power may alternatively be supplied from a subsea power distributionsystem with a single AC or DC cable connected to the host. Hydraulicoil, chemicals, methanol and control signals are communicated to thesubsea installation by use of a service umbilical. In case of using oneflowline only, it can be integrated into the service umbilical togetherwith the electrical cables providing a single flexible connectionbetween the subsea production system and host facility. This combinationmay have a major cost reduction impact, especially for very long tieback distances.

[0022] Power fluid supplied subsea can also be utilized to providedownhole pressure boosting of the separated oil phase from theseparator. Pressure boosting may also be by boosting the wellfluidflowing into the separator. Both ESP's and HSP's can be used to lowerthe wellbore flowing pressure and thereby increasing the inflow ratefrom the reservoir.

[0023] The conventional and Side Valve Trees have a basic philosophicaldifference in the sequence of installing the tubing completion. Theconventional system is normally thought of for the drilling andcompletion scenario, which means that the tubing hanger is installedinto the wellhead immediately after installation of the casing strings.This is done while the BOP (Blow-out Preventer) stack is still connectedto the wellhead. The tree is then installed on the completed wellheadwith a dedicated, open water riser system. Flowlines are then connectedto the tree. This tends to be very efficient when it is known that awell will be completed. The down side of the conventional tree system isthat any workover of the wellbore, where the completion is recovered,involves recovery of the tree. This means that flowlines and umbilicalconnectors, along with jumpers, must be disconnected prior to treerecovery. The tree is recovered with the dedicated riser system, thenthe BOP system is installed on the wellhead and only then the completioncan be recovered.

[0024] A dual function x-mas tree is utilized when it is desirable toinject and produce through the same tree/wellhead. The advantage to thiscase is the elimination of drilling a dedicated injection well.

[0025] Downhole pressure control is required in the form of downholesafety valves. Both the inner and outer strings require safety valves.The inner string could be production or injection, and the second string(outer) would be injection. Further, if two sets of DHSV's (DownholeSafety Valves) are used then it will be assumed that each valve (innerand outer) will be controlled on an individual hydraulic function. TheHorizontal Side Valve Tree provides the best solution for thisconfiguration. The main reason for this is the advantage of being ableto pull the downhole completion through the tree, which is not possiblein the case of conventional trees.

[0026] The Side Valve Tree (SVT) is normally intended for a batchdrilling scenario, or when planned workovers are anticipated. The SVTalso is used when artificial lift means are incorporated, Such as anElectrical Submerged Pump (ESP) is either planned or used later in thefield life. Vertical access is accomplished using a Blow-Out Prevention(BOP) system, or other dedicated system. Since the valves are located onthe side of the spool, full bore access (usually 18¾″ diameter) isachieved. Flowlines are not disturbed during any of the workoverinterventions. In essence, the SVT becomes a tubing spool and thecompletion is installed into this spool. The down side of the SVT systemis that the BOP stack must be recovered between drilling the casing anddrilling the completion. The SVT is landed on the wellhead, and the BOPis re-installed on top of the SVT.

[0027] The Independently Retrievable Tree (IRT), currently beingdeveloped, combines the most desirable features of the conventionalx-mas tree and the SVT. This type of tree is considered a truethrough-bore tree. Simply stated, the IRT allows recovery of either thetree or the tubing hanger independent of each other. Installation orderof this system is also independent of each other. This means that thetubing hanger can be installed as in a conventional system, and theninstall the tree. The system also allows for installation of the treefirst, like the SVT system, then install the completion. This type ofdesign provides for maximum flexibility compared with the previoussystems. When more equipment being installed downhole the need forregular retrieval of the completion increases, which favours the SideValve and IR Tree.

[0028] The use of a standard production Side Valve Tree in combinationwith an injection spool would be considered a highly feasible solution.This solution utilizes existing technologies for the primary equipment.Tubing spools are frequently used in subsea wellhead productionequipment as an alternative means for tubing hanger support. This“stacked” tree arrangement would be much the same as a tree-on-tubingspool configuration. This solution utilizes existing technologies forthe primary equipment. An increased number of penetrations are requiredfor wellbore control. Additional penetrations are an expansion ofcurrent technology, which is considered both feasible and mature.

[0029] The present invention takes advantage of the newest developmentsin tree technology, to make it possible to produce and inject (includingpower fluid supply) through the same x-mas tree. However, the presentinvention is not limited to the use of the above mentioned trees, sinceit is also possible to realise the invention through more conventionaltechnology.

[0030] The main object of the present invention is to facilitate thesupply of power fluid to downhole turbines or engines in a plurality ofwells, and further facilitate the control of downhole separators.

[0031] A further object of the present invention is to enable anaccommodation of the equipment to the changing requirement over thelifespan of the well, e.g. enable transportation of producedhydrocarbons in both headers in the beginning of the lifespan and enablewater injection through one header when the wells are producingincreasingly larger ratios of water.

[0032] Another object of the present invention is to reduce costs byreducing the need for equipment, and thereby also reducing theinstallation costs and service costs.

[0033] A further object of the present invention is to make it possibleto use only one flowline coupled to the subsea manifold, whilst stillretaining the possibility of supplying power fluid to turbines in thewells.

[0034] Still another object of the present invention is to enable roundpigging (for cleaning and/or monitoring) in a single flowline connectedto a manifold.

[0035] This is achieved according to the invention by the characterizingfeatures of the enclosed claims 1, 3, 9, 28, 31 and/or 35.

[0036] The independent claims are defining further embodiments andalternatives of the invention.

[0037] A detailed description of the present invention is to be made, asan example only, under reference to the embodiments shown in theenclosed drawings, wherein:

[0038]FIG. 1a shows a process flow diagram of a conventional layout of aproduction manifold and well according to prior art.

[0039]FIG. 1b illustrates an alternative isolation valve configurationto what is shown in FIG. 1a. The manifold has reduced number ofconnections between producing wells and manifold headers. Valves forrouting production to each of the headers are grouped together for twowells.

[0040]FIG. 2a shows a layout of a production manifold and well accordingto a first embodiment of the present invention, showing power watersupplied from a platform or from the shore.

[0041]FIG. 2b illustrates an alternative configuration to what is shownin FIG. 2a. and similar to what is shown in FIG. 1b.

[0042]FIG. 2c illustrates an alternative configuration with arrangementof isolation valves similar to what is show in FIG. 2b.

[0043]FIG. 3 shows a layout of a production manifold and well accordingto a second embodiment of the present invention, showing a diversion ofthe embodiment of FIG. 2b, with a charge pump.

[0044]FIG. 4a shows a layout of a production manifold and well accordingto a fourth embodiment of the present invention, showing power watersupplied from a free flowing water producing well.

[0045]FIG. 4b shows a layout of a production manifold and well accordingto a fifth embodiment of the present invention, showing power watersupplied by a pump in a water producing well.

[0046]FIG. 4c shows a layout of a production manifold and well accordingto a sixth embodiment of the present invention, showing a diversion ofthe embodiment of FIG. 4b, with a closed circuit driven hydraulicpowered pump for lift in the water producing well.

[0047]FIG. 4d shows a layout of a production manifold and well accordingto a seventh embodiment of the present invention, showing a diversion ofthe embodiment of FIG. 4b, with an electrically driven pump for lift inthe water producing well.

[0048]FIG. 5a shows a layout of a production manifold and well accordingto an eighth embodiment of the present invention, showing power watersupplied from surrounding seawaters pressurized by a subsea pump withdischarge commingled with formation water and injected.

[0049]FIG. 5b shows a layout of a production manifold and well accordingto a ninth embodiment of the present invention showing a diversion ofthe embodiment of FIG. 5a, with discharge water being released to thesurrounding seawaters.

[0050]FIG. 6 shows a layout of a production manifold and well accordingto a tenth embodiment of the present invention, showing a closed circuitdriven hydraulic powered pump in the hydrocarbon producing well.

[0051]FIG. 7 shows a layout of a production manifold and well accordingto an eleventh embodiment of the present invention, showing the use ofproduced hydrocarbons as power fluid.

[0052]FIG. 8 shows a layout of a production manifold and well accordingto a twelfth embodiment of the present invention, comprising the use ofonly one flowline.

[0053]FIG. 9 shows a conventional gas lift arrangement used in anarrangement according to the invention of the type shown in FIG. 2a.

[0054]FIG. 9b shows a layout of an arrangement for providing gas liftaccording to an embodiment of the present invention, with gas supply inone of the flowlines.

[0055]FIG. 9c shows a layout of an arrangement according to theinvention for providing gas for artificial lift locally.

[0056]FIG. 10a shows a layout of an arrangement according to the presentinvention comprising a downhole hydraulic turbine/pump converter forboosting the pressure of the well fluid coupled in series with theturbine/pump converter for pumping separated water.

[0057]FIG. 10b shows a similar layout to FIG. 10a, but with a parallelconfiguration with dedicated wellhead chokes for the turbine/pumpconverter for the well fluid and the turbine/pump converter forseparated water.

[0058]FIG. 10c shows a similar layout to FIG. 10b, but with parallelconfiguration of the turbine/pump converter for the well fluid and theturbine/pump converter for separated water with a downhole control valvefor the turbine/pump converter for the well fluid.

[0059]FIG. 11a shows a layout of a downhole arrangement for gas-liquidseparation upstream of a liquid-liquid separation and with a gasscrubber.

[0060]FIG. 11b shows a similar layout to FIG. 11a, but without ascrubber.

[0061]FIG. 11c shows a gas-liquid separation only with a gas scrubber.

[0062] For the description of all embodiments hereafter the featurescorresponding fully with the previous embodiment, or embodiment referredto, is not described in detail. It is to be understood that the parts ofthe embodiment not described in detail fully complies with the previousembodiment or any other embodiment referred to.

[0063] When in the following specification the term well fluid is used,this means the fluid that is extracted from the formation. The wellfluid may contain gas, oil and/or water, or any combinations of these.When in the following specification the term production fluid is used,this means the portion of the well fluid that is brought from thereservoir to the seabed.

[0064]FIG. 1a illustrates a prior art production situation layout withfour wells, each connected to the manifold by mechanical connectors 3 a,3 b, 3 c, 3 d. For illustration the well connected to the mechanicalconnector 3 c the layout is displayed in detail. However, it should beunderstood that the layouts for the other four wells are of a similarkind.

[0065] The well connected to the mechanical connector 3 c comprises adownhole production tubing 40 (only partly shown), leading to apetroleum producing formation 80, a subsea wellhead 1 and a productionchoke 2. The production choke is, via the mechanical connector, incommunication with a manifold, generally denoted 41.

[0066] The manifold comprises two production headers 6 a and 6 b. A setof isolation valves 4 a, 5 a; 4 b, 5 b; 4 c, 5 c; 4 d, 5 d for each wellare provided to make it possible to route production flow into one orthe other of the headers 6 a and 6 b.

[0067] At one end of the manifold a removable pipe spool 9 jointstogether the two headers 6 a, 6 b via two mechanical connectors 10 a, 10b. An hydraulic operated isolation valve 11 a is provided in the firstheader 6 a and together with a ROV valve 11 b in the second headerenables removal of the pipe spool when closed for tie-in of anotherproduction template

[0068]FIG. 1b show a deviated layout of the layout shown in FIG. 1a.Here two and two wells are coupled together to the manifold. As in FIG.1a connector 3 a is connected to the first header 6 a via isolationvalve 5 a, and to the second header 6 b via isolation valve 4 a,connector 3 b is connected to the first header 6 a via isolation valve 5b, and to the second header 6 b via isolation valve 4 b. Opposite to thelayout of FIG. 1a, isolation valves 5 a and 5 b are connected with eachother, and isolation valves 4 a and 4 b are connected with each other.This layout makes it possible to choose which of the headers 6 a and 6 bthe connectors are to be in communication with. Opening valves 5 a and 4b, and closing valves 5 b and 4 a will set connector 3 a incommunication with the first header 6 a and connector 3 b incommunication with the second header 6 b. Opening valves 4 a and 5 b,and closing valves 4 b and 5 a will set connector 3 a in communicationwith the second header 6 b and connector 3 b in communication with thefirst header 6 a. Connectors 3 c and 3 d are connected to the manifoldthrough valves 4 c, 4 d, 5 c, 5 d in a similar way as connectors 3 a and3 b. In all other respects the two layouts of FIGS. 1a and 1 b aresimilar.

[0069] In FIG. 1c an actual manifold is illustrated. Similar referencenumbers in FIG. 1b and FIG. 1c denotes the same details. In FIG. 1c thetwo headers 6 a and 6 b, with connectors 7 a, 7 b are shown. Isolationvalves 4 a, 5 a; 4 b, 5 b; 4 c, 5 c; 4 d, 5 d are connected to therespective headers. Connectors 3 a, 3 b, 3 c and 3 d are connected tothe isolation valves.

[0070] The manifolds according to FIGS. 1a and 1 b works in thefollowing way:

[0071] Oil, gas and water flows from the reservoir into the wells andtrough the production tubing 40 to the subsea wellhead 1, and is routedto the manifold 41 via the production choke 2 and the mechanicalconnector 3 c. One of the isolation valves 4 c, 5 c will be closed andthe other one will be open and allow for production to be routed intoeither the first 6 a or to the second header 6 b. The production is thentransported by natural flow to topsides or shore in flowlines 8 a, 8 bconnected to the manifold 41 by mechanical tie-in connectors 7 a, 7 b.

[0072] It is possible also to bring in production fluids from anothermanifold by connecting this to the manifold instead of the pipe spool.The isolation valve 11 fitted in the first header enables the otherheader to be freed up to act as a service line.

[0073]FIG. 2a shows a first embodiment of the present invention, whichis a development of the manifold and well layout shown in FIG. 1. Inaddition to the isolation valves 4 a, 5 a; 4 b, 5 b; 4 c, 5 c; 4 d, 5 dit comprises a third isolation valve 14 a, 14 b, 14 c, 14 d for eachwell. A relief valve 18 is also provided.

[0074] A different layout is shown for the well connected to themechanical connector 3 c. The well comprises a production pipeline 40,which is connected to a downhole hydrocarbon-water separator 13. It alsocomprises an injection pipeline 42 connected to the separator via adownhole pump 17. The downhole pump 17 is driven by a downhole turbineexpander 16. The turbine 16 is connected to the manifold via thewellhead (x-mas tree) 1, an injection choke 15 and a second mechanicalconnector 43.

[0075] In all other respects the layout of FIG. 2a is identical with thelayout of FIG. 1a.

[0076]FIG. 2a illustrates the concept of combining hydrocarbonproduction and supply of power fluid (water) to one (or several)downhole located hydraulic turbine/pump converter(s). Wellfluid from theproduction reservoir 80 is via the production tubing routed to thedownhole hydrocarbon-water separator 13. In the separator thehydrocarbons are separated from the water. Such a separator is knownfrom e.g. WO 98/41304, and will therefore not be explained in detailherein. Hydrocarbons from the separator flows to the subsea productionx-mas tree 1. Adjustment of the production choke 2 allows for individualcontrol of production of the well producing to a common header 6 a. Allproduction fluids from the wells are routed to the first header 6 a bysetting the isolating valves 5 a, 5 b, 5 c, 5 d in open position and theisolating-valves 4 a, 4 b, 4 c 4 d in closed position.

[0077] The isolating valve 11 in the first header 6 a is set to closedposition, thus forcing all produced hydrocarbons to flow via the firstflowline 8 a to a platform or to shore for further processing.

[0078] Pressurized power fluid (water) is routed via the second flowline8 b to the manifold 41 and into the second header 6 b. The isolatingvalves 14 a, 14 b, 14 c, 14 d are set in open position and allows powerfluid to be routed from the second header 6 b via the injection chokevalve 15 to the injection side of the x-mas tree 1, which is of a dualfunction type (suitable for both production and injection). A productionsystem may also consist of one or more well not having a downholeseparator. In such a case the valve 14 is not relevant.

[0079] The power fluid is routed to the downhole turbine expander 16either via the annulus formed by the production casing and theproduction tubing or by a separate injection tubing in a dual completionsystem. Water separated from the hydrocarbons in the downhole separator13 is routed to a downhole pump 17. This pump is mechanically driven bythe turbine, e.g. via a shaft 44. Power fluid expand to the pressure onthe discharge side of the pump 16 where it is commingled with theseparated, produced water and routed into the injection line to bedisposed in a reservoir 81 suitable for water disposal and/or pressuresupport.

[0080] The rate of power fluid supplied to the turbine is regulated byoperating the seabed located injection choke 15. For application with agravity type downhole separator 13 a suitable rate of power fluid isapplied in order to maintain a pre-set oil-water interface level and/ormeasurement of injection water quality. If a hydrocyclone type downholeseparator is used, this is controlled by either flow-split (ratiobetween overflow and inflow rates) or by water-cut measurement in thehydrocarbon outlet. The total rate of power fluid supplied to the secondheader 6 b is regulated to obtain a pre-set constant pressure in thesecond header 6 b. The relief valve 18 may, if required, be integratedinto the header 6 b enabling surplus fluid to be discharged to thesurrounding seawater.

[0081] The manifold and well of FIG. 2a may also be configured toproduce hydrocarbons in a conventional way without injection. By closingthe isolating valves 14 a, 14 b, 14 c, 14 d the injection will be cutoff. By opening the isolating valves 4 a, 4 b, 4 c, 4 d, productionfluid will be lead into the second header 6 b, and production will takeplace in the same conventional way as in FIG. 1a.

[0082]FIG. 2b show a deviated layout from FIG. 2a. The arrangement ofconnectors 3 a, 3 b, 3 c, 3 d, valves 4 a, 4 b, 4 c, 4 d, 5 a, 5 b, 5 c,5 d and their connection to the first header 6 a and the second header 6b is the same as in FIG. 1b. In addition to this the valves 14 a and 14b are connected to each other and to the line between valves 4 a and 4b. The valves 14 c and 14 d are connected to each other and valves 4 cand 4 d in a similar way. The second connector 43 is replaced with acommon connector 3 c for the production fluid line 40 and the powerfluid line. I all other respects the layout of FIG. 2b is identical tothe layout of FIG. 2a. Supply of power fluid is branched off from theisolation valve arrangement, with isolation valves 4 d and 5 d closed,routed to the x-mas trees via valves 14 c and a multi bore connector 3c.

[0083]FIG. 2c is a further deviation of the layout of FIG. 2b. Here thevalves 14 a and 14 b are connected to each other, but not to the linebetween valves 4 a and 4 b. The same applies for valves 14 c and 14 d.In all other respects the layout of FIG. 2c is identical to the layoutof FIG. 2b. Power fluid is supplied from pipe connection to the secondheader 6 b and routed via the valves 14 a, 14 b, 14 c, 4 d and a multibore connector to the wells.

[0084]FIG. 2d shows an actual manifold. Similar reference numbers inFIG. 2b and FIG. 2d denotes the same details. In FIG. 2d the two headers6 a and 6 b, with connectors 7 a, 7 b are shown. Isolation valves 4 a, 5a; 4 b, 5 b; 4 c, 5 c; 4 d, 5 d are connected to the respective headers.Connectors 3 a, 3 b, 3 c and 3 d are connected to the isolation valves.The third isolation valves 14 a, 14 b, 14 c, 14 d are also shown, aswell as the valves 11 a and 11 b.

[0085]FIG. 3 is a variant embodiment of FIG. 2b and illustrates theconcept of utilizing a subsea located speed controlled charge pump 19.Power fluid may be supplied from a platform, shore or other subseainstallations. The pump is connected to the second header via an inletside shutoff valve 60, a discharge side shutoff valve 61 and a connector62. A bypass valve 63 is also provided to enable bypass of power fluidpassed the charge pump 19. The pump 19 shown is driven electrically, butmay also be driven by any other suitable means.

[0086] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d.

[0087] The bypass valve 63 will in such a case be open, to bypass theproduction fluids passed the pump 19.

[0088]FIG. 4a is a further embodiment and illustrates the application ofa subsea located speed controlled pump 19 connected to the second header6 b within the manifold 41 supplying power fluid as free flowing watertaken from a downhole aquifer 82, via a formation water line 50, a waterproduction x-mas tree 49, a pipeline 45, a connector 66 and a shutoffvalve 67. The charge pump 23 is utilized for power supply to thedownhole turbine 16. The charge pump 26 is shown electrically driven,but may also be driven by any other suitable means. An isolation valve21 is placed in the second header 6 b and when closed prevent powerfluid from entering the connected flowline 8 b. A crossover pipe spool46 with an isolation valve 22 connects the two headers 6 a, 6 b. Withthis valve in open position produced hydrocarbons can be routed from thefirst header 6 a into both flowlines 8 a, 8 b.

[0089] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d. The isolation valve 67will be closed to avoid production fluid entering the pump 19.

[0090]FIG. 4b illustrates the same concept as outlined in FIG. 4a, withwater supplied from a downhole aquifer 82. The water retrieving systemcomprises a downhole pump 26, driven by a downhole turbine 25 via ashaft 48. The turbine is fed with power fluid via a power fluid line 52,which is supplied via a choke valve 24.

[0091] The pump 26 feeds formation water to the seabed via a formationwater line 50 and a water production x-mas tree 49. The water ispressurized by a subsea located speed controlled pump 23 connected tothe second header 6 b via the connector 66 and the shutoff valve 67, andconnected to the formation water line via connector 66, a secondconnector 68 and a second shutoff valve 69.

[0092] A split flow is taken from the discharge side of the subseacharge pump 23 at 51 and routed to the downhole turbine 25 via the chokevalve 24 located at the x-mas tree 49. The downhole turbine 25 drivesthe downhole pump 26 as the power fluid expands to the pump dischargepressure at the discharge side of the pump 26, where it is commingledwith the formation water and brought to the seabed where the fluid againis utilized as power fluid to the production wells. This alternative issuited when mixing, of seawater and produced water will cause problems,for example scaling.

[0093] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d. The isolation valve 67will be closed to avoid production fluid entering-the pump 23 or theturbine 25. The choke valve 24 may also be in a closed position.

[0094]FIG. 4c illustrates a variant of the concept described in FIG. 4b.Here a closed loop system 53 for power fluid to the downhole turbine25/pump 26 hydraulic converter is utilized. A charge pump 27 in theclosed loop system 53 is electrically powered, speed controlled and islocated at the seabed and integrated into the subsea production system.

[0095] The subsea charge pump 23 may be omitted if sufficient flow andpressure can be generated in the second header 6 b by use of theformation water supply pump 26 only. The water supply pump 26 may alsobe driven electrically instead of by a power fluid driven turbine.

[0096] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valved 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d. The isolation valve 67will be closed to avoid production fluid entering the pump 23 or theturbine 25.

[0097]FIG. 4d illustrates a concept with formation water supplied froman aquifer 82 by use of an electrically driven submerged pump 28 (ESP)The ESP is located downhole and provides sufficient pressure of thepumped fluid for the suction side of the charge pump 23 located on theseabed. For particular applications (especially for deepwaterdevelopments) formation water may be drawn from an aquifer and deliveredto the seabed at acceptable charge pump suction pressure without need ofdownhole pressure boosting.

[0098] Like in the embodiment of FIG. 4c the charge pump is connected tothe second header 6 b via a connector 66 and a shutoff valve 67. and tothe formation water line 50 via the connector 66 and a shutoff valve 69.

[0099] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d. The isolation valve 67will be closed to avoid production fluid entering the pump 23.

[0100]FIG. 5a is a further embodiment and illustrates the application ofa subsea located speed controlled pump 19 connected to the second header6 b within the manifold 41 supplying power fluid as seawater taken fromthe surrounding sea via a pipeline 45, connector 64 and shutoff valve65. Solids and particles are removed by use of a filtration device 20 onthe pump suction side. An isolation valve 21 is placed in the secondheader 6 b and when closed prevent power fluid from entering theconnected flowline 8 b. A crossover pipe spool 46 with an isolationvalve 22 connects the two headers 6 a, 6 b. With this valve in openposition produced hydrocarbons can be routed from the first header 6 ainto both flowlines 8 a, 8 b.

[0101] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d. The isolation valve 67will be closed to avoid production fluid entering the pump 19.

[0102]FIG. 5b illustrates the use of an open loop with seawater used aspower fluid. and is a derivation of the embodiment shown in FIG. 5a.Filtrated seawater, filtered by the filter 20, drawn from thesurrounding seawaters, is pressurized by a speed controlled electricalcharge pump 23 and delivered to the second header 6 b via a connector 66and shutoff valve 67. From the second header 6 b the power fluid is fedthrough the choke valve 2 down to the downhole turbine 16 and instead ofcommingling the water with injection water, it is returned through thereturn line 54, at the end 33 of which the water is discharged to thesurroundings.

[0103] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c. 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d.

[0104] The isolation valve 67 will be closed to avoid production fluidentering the pump 23. Return line 54 may also be provided with anisolation valve or check valve (not shown) to avoid seawater enteringline 54.

[0105]FIG. 6 illustrates a concept with a closed loop of power fluid.Here each well is equipped with an additional flowline 54 for returnpower fluid. A mechanical connector 29 connects the line 54 with a thirdheader 30. The third header communicates with a charge pump 23, via aconnector 66 and a line 70.

[0106] The power fluid from the pump 23 is routed via the connector 66,a shutoff valve 67 and the second header 6 b through the choke valve 2,the production x-mas tree 1 on the injection side of the tree and istransported to the downhole turbine 16 in a separate tubing 52 or in anannulus formed by casing, production and power fluid tubing. The powerfluid returns after the turbine expansion process in the return line 54to the subsea wellhead, which is either a separate tube or the annulusif this was not used for feed of power fluid. From the return line thepower fluid is delivered via the mechanical connector 29 to the thirdheader 30 in the manifold.

[0107] An accumulator tank 31 is connected to the line 70 leading fromthe connector 66 to the charge pump 23 inlet side, via a separate line7. The accumulator 31 may also be in communication with a fluid source,e.g. surrounding seawater, through a line 72, to replace power fluidslost due to leakage or for other reasons

[0108] The power fluid return from all wells is routed via the thirdheader 30, from where it is supplied to the charge pump 23, pressureboosted and delivered to the second header 6 b. The third header 30 maybe provided with an intake at 57, provided with a check valve (notshown), as an alternative to the power fluid supply through line 72.

[0109] Also here conventional production according to the functioning ofthe FIG. 1a layout may be achieved by closing the isolation valves 14 a,14 b, 14 c, 14 d and opening the isolating valves 4 a, 4 b, 4 c, 4 d.The isolation valve 67 will be closed to avoid production fluid enteringthe pump 23.

[0110]FIG. 7 illustrates the use of produced oil as power fluid for adownhole hydraulic subsurface pumping system (HSP). The first header 6 ais via a line 55, a shutoff valve 73 and a connector 74, communicatingwith a gas-liquid separator 39, which in turn is communicating with thecharge pump 23. The charge pump 23 is communicating with the secondheader 6 b, via the connector 74 and a shutoff valve 67, which in turnis communicating with the downhole turbine expander 16 via isolatingvalve 14 c, mechanical connector 43, choke valve 15 and x-mas tree 1.The outlet side of the turbine 16 is communicating with the productionflowline 40.

[0111] In line 55 an isolation valve 22 is also mounted.

[0112] The gas-liquid separator 32 is also connected to a gas line 75,which is via the connector 74 and a shutoff valve 76, connected to thesecond header 6 b at the flowline side of a shutoff valve 21

[0113] The isolation valve 22 is set in open position allowing some ofthe produced hydrocarbons to be routed to the gas-liquid separator 32.In the gas-liquid separator 32, the gas is separated and transported tothe second header through line 75. The shutoff valve 21 is closed andthe gas is therefor transported through the flow line 8 b. A suitablerate of the separated oil is supplied to the charge pump 23 anddelivered pressurized to the second header 6 b. The isolation valve 4 cis closed and the isolation valve 14 c is open. The power fluid isthereby routed into the injection side of the dual function x-mas treesvia the injection choke valve 15. When leaving the downhole turbine 16,the power fluid is commingled with the produced hydrocarbons from thedownhole separator 13 and brought to the wellhead (x-mas tree 1). Fromall producing wells the hydrocarbons are routed to the first header 6 avia the open isolation valve 5 c and finally into the first flowline 8 ato be transported to an offshore installation or onshore.

[0114] Also here conventional production according to FIG. 1a may beachieved by closing the isolation valves 14 a, 14 b, 14 c, 14 d andopening the isolating valves 4 a, 4 b, 4 c, 4 d. An isolation valve (notshown) may also be provided in line 45 to avoid production fluidentering the pump 23. Isolation valve 22 will preferably be in a closedposition, shutoff valve 67 will be closed to avoid production fluidsentering the pump 23, and shutoff valve 76 will also be closed to avoidproduction fluids entering the gas-liquid separator 32.

[0115]FIG. 8 illustrates the use of a single flowline 8 instead of thetwo flowlines 8 a and 8 b. The flowline 8 is connected to the twoheaders 6 a and 6 b via a three way valve 76. The three way valve isdesigned to open communication between either of the two headers 6 a and6 b and the flowline 8. In the second header 6 b a shutoff valve 21 isprovided.

[0116] In the shown embodiment, power fluid is supplied from asubterranean water producing well, in the same way as shown in theembodiment of FIG. 4d, however, the downhole pump 28 being omitted. Thepower fluid is also supplied to the turbine 16 and discharged to theinjection line 42 as described in FIG. 4d. However, it should beunderstood that any of the other described embodiments in which powerfluid can be supplied form a nearby source, can be used together withthe single flowline concept.

[0117] During normal production together with water injection the threeway valve will provide for communication of production fluids from thefirst header to the flowline 8, and isolating the second header 6 b formthe flowline 8 and the first header 6 a. The second header being usedfor supply of power fluid.

[0118] The above explained arrangement allows for the use of only oneflowline between the seabed and the platform or facilities onshore. Thiswill enable substantial cost savings.

[0119] The main reason for using two flowlines has been the possibilityto make so called round pigging. This is an alternative to have a piglauncher at one end of the flow line and a pig receiver at the other endof the flowline. The round pigging procedure is a much simpler andinexpensive way of making the necessary pigging.

[0120] Even though the embodiment of FIG. 8 has only one flowline, it isstill possible to perform round pigging. To perform this, first theproduction is stopped. The charge pump 23 is used to purge the flowline8 with valve 21 open and valves 11 a and 11 b closed and with theproducing wells shut off The pump 23 is then shut off, the shutoff valve67 closed, the three way valve set in a position to enable communicationbetween the flowline 8 and the second header and a pig (not shown) isthen launched from the platform or from the onshore facility. Displacedwater may be evacuated to the surroundings, into the hydrocarbonproducing wells, or to a disposal tank (not shown). The position of thepig within the manifold is detected. When the pig driven past the waterinjection branch 45, it is stopped. The valves 11 a and 11 b are opened,the valve 21 is closed and the valve 76 is opened to enablecommunication between the first header 6 a and the flowline 8. Thecharge water pump 23 is started, driving the pig through the spool 9,into the first header 6 a past the valve 11 a. The valve 11 a is thenclosed and the wells are then opened for production into the firstheader 6 a. The production fluids are pushing the pig back through thevalve 76 and the flow line 76 to the host. Normal production is resumed.

[0121] The flowline 8 may be a single integrated flowline, power cableand service umbilical connected to the subsea production systemutilizing, downhole separation and water injection.

[0122]FIG. 9a shows a conventional method for achieving gas lift in ahydrocarbon producing well. The gas is supplied from a distant locationthrough a separate pipe 83. which may be a part of an umbilical. Thepipe 83 is connected to a third header 85 via a connector 84. The thirdheader 85 is at the opposite end connected to a further connector 86,and may be connected through this with further manifolds.

[0123] Via connector 3 c the third header 85 is connected with a chokevalve 87 and further, via x-mas tree 1, with a gas line 88, which inturn is connected to the production tubing 40, to transport gas into theproduction tubing 40.

[0124] The parts of FIG. 9a not specifically described are identicalwith FIG. 2a.

[0125]FIG. 9b illustrates a gas supply arrangement for gas liftaccording to an embodiment of the present invention. Gas is suppliedfrom a distant location through a gas pipe 83. The gas is branched offbefore the closed shut off valve 21 and lead through a shut off valve 89to a third header 85, and further through connector 3 c, choke valve 87and gas line 88 to production tubing 40.

[0126] Supply of power fluid to the downhole turbine 16 is transportedthrough the second header 6 b on the other side of the closed shut offvalve 21 from the gas supply. In all other respects the layout isidentical with FIG. 2a.

[0127] Opposite to the arrangement of FIG. 9a it is, with thearrangement of FIG. 9b, possible to perform gas lift with only twoflowlines 8 a and 8 b connected to the manifold.

[0128]FIG. 9c illustrates the use of a local gas lift re-cycling loop atthe production area. The concept is illustrated in conjunction withwater injection, but is relevant also with conventional production. Wellfluid is routed from the first header 6 a, with isolation valve 102closed. through a shut off valve 90 c and a connector 91 to a gas-liquidseparator 92. The liquid phase is returned through the connector 91 anda shut off valve 90 d to the first header at the downstream side of thevalve 102 and flow by pressure to the host via the first flowline 8 a. Asuitable rate of gas extracted from the separator 92 is pressurized by aspeed controlled compressor 93 and delivered through the connector 91and a shut off valve 90 a to a third header 85. The rest of the gas islead though an isolation valve 94, the connector 91 and a shut off valve90 b to the second flowline 8 b at the downstream side of the closedvalve 21 and transported to the host. The gas in the third header 85 isfrom here distributed to the individual wells by use of a choke valve 87situated on x-mas tree or on the manifold. The concept may also includere-cycling loops on the compressor or within the manifold.

[0129]FIG. 10a shows power fluid supplied through the second header 6 a,though the connector 3 c, choke valve 15 and x-mas tree 1 to a turbine95. Turbine 95 drives, through a shaft, a pump 96 for pumping productionfluid to provide artificial lift.

[0130] From the turbine 95 the power fluid is lead to the turbine 16,driving the pump 17 pumping the separated water. After leaving theturbine 16 the power water is commingled with the separated water andinjected in an injection formation 81.

[0131] Power fluid may alternatively be supplied first to the turbine 17and then routed to the turbine 95. When two turbines are coupled inseries, the turbine used for boosting production fluid will be design togive a suitable pressure increase whilst the one injecting water isoperated with respect to maintaining separator performance, the controlof the latter taking precedence over the former.

[0132]FIG. 10b shows a diversion of the embodiment of FIG. 10a. Thepower water from the second header 6 b is split at 103. A first part ofthe water is lead down through choke valve 15 and x-mas tree 1 toturbine 16, driving pump 17 pumping separated water. A second part ofthe power water is lead through a second choke valve 104 and the x-mastree 1 to the turbine 95, driving the pump 96 pumping production fluid.The water from the turbine 16 and theiturbine 95 is commingled with theseparated water and injected into formation 81. As an alternative, thewater from the outlet side of one of the turbines may be routed into theinlet side of the other.

[0133]FIG. 10c shows an embodiment of the invention with both gas liftand pumping of production fluid. Gas lift is provided as shown in FIG.9a, but could just as well be provided by the means shown in FIG. 9b or9 c.

[0134] The power water is lead though the choke valve 15 and the x-mastree 1. At 105 the water is split. A first part of the water is leaddown to the turbine 16, driving the pump pumping separated water. Thesecond part of the power water is lead through a control valve 97 and tothe turbine 95, driving the pump 96 pumping production fluid. The waterfrom turbines 16 and 95 is commingled with the separated water andinjected in formation 81. Instead of control valve 97 a fixed orificemay also be used.

[0135] Suitable flow-split at 105 can also be accomplish by design ofturbine vanes. stages, inlet piping and restriction orifices. The showndownhole hydraulically or electrically operated control valve 97 cantogether with the choke valve 15 control the ratio and amount of powerfluid supplied to the two turbines and thereby facilitating control ofthe boosting of production fluid independent of the control of theinjection of water. Gas lift may also be used for artificial lift incombination with pressure boosting the oil to seabed as explained below.

[0136]FIG. 11a illustrates the use of a multiphase (gas-oil-water)downhole separation system. Well fluid enters a gas-liquid separator 98where the gas phase is extracted and routed through line 99 past theoil-water separator 13 in a pipe to a downstream gas-liquid scrubber100. Liquid entrained in the gas flow is separated using high g-forceand routed back to the separator 13 though line 101. The scrubber 100 isplaced at suitable elevated level allowing the liquid to be drained bygravity through the line 101 into the oil-water separator 13. The cleangas is injected into the oil phase in production line 40 for flow to thewellhead 1. Optimal performance requires a well pressure balancedsystem. When water entrainment in oil is not a critical issue thescrubber stage with the drainage pipe may be omitted.

[0137]FIG. 11b shows a two stage mutltiphase (gas-water-oil) downholeseparation without a gas scrubber. The production fluid is lead into agas-liquid separator 98, in which the gas is separated from the liquid.The gas is lead through a pipe 99 and into the production line 40, whereit is used for gas lift. The liquid is lead into a oil-water separator13, where oil is separated to the production line 40 and water isseparated to be pressurised by pump 17 and injected together with powerwater from turbine 16.

[0138] A downhole turbine/pump hydraulic converter may be used also inconnection with the embodiments of FIGS. 11a and 11 b. The pump may beplaced before the gas-liquid separator 98, between the gas-liquidseparator 98 and the liquid-liquid separator 13 or after theliquid-liquid separator 13.

[0139]FIG. 11c illustrates the use of a two stage downhole gas-liquidseparation system. Well fluid enters a gas-liquid separator 98 where thegas phase is extracted and routed in a pipe 99 to a gas-liquid scrubber100. Liquid entrained in the gas flow is separated using high g-force.The scrubber 100 is placed at suitable elevated level allowing theliquid to be drained by gravity through a pipe 101 to upstream of thegas-liquid separator 98, and may consist of one or more separationstages. Dry gas exit the scrubber 100 and flows to the wellhead 1 eitherin production tubing 40 or in an annulus formed by the casing and theproduction tubing. Water is taken from the separator 98, pressurized bypump 17 and injected together with power fluid exiting turbine 16.

[0140] Optimal performance requires a well pressure balanced system. Theseparation system is also applicable when condensate is to bere-injected back into the formation. This embodiment is preferable forwells which mainly produce gas with little oil.

[0141] The separators may be of one of the types described in Norwegianpatent application No. 2000 0816 by the same applicant.

[0142] For all illustrated embodiments of the present invention anadditional line (not shown) and an additional isolation valve (notshown) may be provided to make it possible to route the productionthrough the second header and the power fluid and/or injection fluidthrough the first header.

[0143] Instead of injecting the water into the formation, the water mayalso be transported LIP to the surface in the return line 54 or aseparate line (not shown) for subsequent processing and/or disposal.

[0144] All the described production alternatives can be enhanced asrequired to include subsea processing equipment for gas-liquidseparation. further hydrocarbon-water separation by use of electrostaticcoalesces, single phase liquid pumping, single phase gas compression andmultiphase pumping. In case of subsea gas-liquid separation, gas may berouted to one flowline whilst the liquid is routed to the other.

[0145] Any connector may be of horizontal or vertical type. Return andsupply lines may be routed through a common multibore connector or bedistributed using independent connectors.

[0146] Choke valves may be located on the x-mas tree as shown inattached figures, but can also be located on the manifold. The valvesmay if required be independent retrievable items. Choke valves subseaare normally hydraulic operated but may be electrical operated forapplication where a quick response is needed.

[0147] Electrically operated pumps are not illustrated in attachedfigures with utility systems for re-cycling, pressure compensation andrefill. One pump only is show for each functional requirement. However,depended on flowrates, pressure increase or power arrangement withseveral pumps connected in parallel or series may be appropriate.

[0148] The present invention also provides for any working combinationof the embodiments shown herein. The invention is limited only by theenclosed independent claims.

1. Method of controlling a downhole separator, for separatinghydrocarbons and water, the hydrocarbons leaving the separator flowingthrough a x-mas tree and a first header in a manifold, wherein a powerfluid is used to drive a downhole turbine/pump hydraulic converter, thepump in the downhole turbine/pump hydraulic converter pumping separatedwater, characterized in that the power fluid for the downholeturbine/pump hydraulic converter is fed through a second header in themanifold, a adjustable valve and a x-mas tree to the turbine in thedownhole turbine/pump hydraulic converter, the rate of pumping beingcontrolled by the rate of power fluid based on measures of water levelin the separator, flow-split or oil and/or water entrainment of theseparated phases.
 2. The method of claim 1, characterized in that therate of pumping of separated water is controlled by a charge pump incommunication with the second header.
 3. Method of supplying power fluidto a downhole turbine/pump hydraulic converter, characterized in thatthe method comprising the steps of: providing a manifold having a firstand a second header, providing communication between the first headerand a well fluid line in the well bore. providing communication betweenthe second header and the turbine of the downhole turbine/pump hydraulicconverter, and supplying power fluid to the turbine through the secondheader.
 4. The method of claim 1 or 3, characterized in that the waterfrom the pump in the downhole turbine/pump hydraulic converter is usedfor injection in the formation.
 5. The method of any of the precedingclaims, characterized in that surrounding seawater is used as powerfluid and is either injected into the reservoir together with theseparated produced water or returned to the seabed and discharged to thesurrounding sea.
 6. The method of any of the preceding claims,characterized in that the power fluid is extracted form a formation andis free flowing from an aquifer to the seabed or pumped to the seabedusing a downhole electrical operated pump or a downhole turbine/pumphydraulic converter.
 7. The method of claim any of the preceding claims,characterized in that the power fluid is circulated in a closed loopwith pressure increase by use of a seabed located charge pump and thatthe power fluid is returned to the manifold in a third header.
 8. Themethod of any of the claim 1-4, characterized in that the power fluid isseparated oil pressurized by a charge pump and routed to the downholeturbine in the downhole turbine/pump hydraulic converter and that thepower fluid is discharged to the wellfluid brought to the manifold atthe seabed.
 9. A subsea petroleum production arrangement for producinghydrocarbons from a plurality of wells, comprising a manifold having afirst and a second header and isolating valves for isolating the firstor the second header from the respective wells, at least the firstheader being in selective fluid communication. via a respectiveadjustable valve and a respective x-mas tree, with respectivehydrocarbon transporting lines in the wells, for transportation ofhydrocarbons, at least one of the wells having a downhole separator forseparating hydrocarbons and water and a downhole turbine/pump hydraulicconverter for pumping separated water, characterized in that the secondheader is in communication with a power fluid supply and via a powerfluid adjustable valve in further communication with a turbine in thedownhole turbine/pump hydraulic converter.
 10. The arrangement of claim9, characterized in that the second header is in communication with apower fluid source on an offshore installation or onshore.
 11. Thearrangement of claim 9, characterized in that the second header is incommunication with a power fluid source of a subterranean well.
 12. Thearrangement of claims 9, 10 or 11, characterized in that the power fluidis water.
 13. The arrangement of claims 9, 10, 11 or 12, characterizedin that a subsea charge pump is provided for pressurizing the powerfluid before entering the wells.
 14. The arrangement of claim 13,characterized in that the second header is in communication with thesurrounding seawaters, and that seawater is used as power fluid.
 15. Thearrangement of claim 12, 13 or 14, characterized in that the dischargeside of the turbine in the downhole turbine/pump hydraulic converter isin communication with the discharge side of the pump of the downholeturbine/pump hydraulic converter.
 16. The arrangement of claim 154,characterized in that the discharge side of the turbine and the pump ofthe downhole turbine/pump hydraulic converter is in communication withan injection zone in a formation being injected with water.
 17. Thearrangement of any of the claims 9-16, characterized in that thedischarge side of the pump in the downhole turbine/pump hydraulicconverter is in communication with a return line returning the powerfluid to the surface or seabed.
 18. The arrangement of claim 17,characterized in that the return line is in communication with a thirdheader in communication with the charge pump, to return the power fluidto the inlet side of the charge pump.
 19. The arrangement of claim 17,characterized in that the return line is in communication with thesurrounding seawaters to discharge the power fluid into the seawaters.20. The arrangement of claim 10, characterized in that a second pump isprovided in the subterranean power fluid source well.
 21. Thearrangement of claim 20, characterized in that the second pump is anelectrically driven pump.
 22. The arrangement of claim 20, characterizedin that the second pump is driven by a separate power fluid source. 23.The arrangement of claim 13 and 20, characterized in that the secondpump is a downhole turbine/pump hydraulic converter, the turbine of thesecond downhole turbine/pump hydraulic converter being in communicationwith the discharge side of the charge pump.
 24. The arrangement ofclaims 9 and 13, characterized in that the power fluid is hydrocarbons,and that the first header is in communication with the second header viathe charge pump.
 25. The arrangement of claim 24, characterized in thatthe discharge side of the pump of the downhole turbine/pump hydraulicconverter is in communication with the hydrocarbon transporting line.26. The arrangement of any of the preceding claims, characterized inthat isolation valves are provided to isolate the second header from thepower fluid lines and open communication between the second header andthe hydrocarbon transporting lines, thereby enabling transportation ofhydrocarbons in both headers.
 27. The arrangement of any of thepreceding claims, characterized in that isolation valves are provided toisolate the power fluid lines from the second header, open communicationbetween the first header and the power fluid lines, isolate thehydrocarbon transporting lines from the first header and opencommunication between the hydrocarbon transporting lines and the secondheader, to enable hydrocarbon transport in the second header and powerfluid transport in the first header or vice versa.
 28. A method forperforming pigging of a subsea manifold, the manifold comprising a firstand a second header being in selective communication with each other ata first respective end, characterized in that a single flowline is inselective communication with the first and the second header at a secondrespective end, wherein a pig is fed into the flowline and directed intothe first header. the pig is thereafter led into the second header andsubsequently led into the flowline.
 29. The method of claim 28,characterized in that the pig is driven from the first to the secondheader and into the flowline by pressure from a charge pump coupled tothe first header.
 30. The method of claim 29, characterized in thatpressure supplied from a source at a platform or onshore drives the piginto the first header.
 31. A subsea petroleum production arrangement,comprising a subsea manifold having a first and a second header inselective communication with each other at a first respective end,characterized in that a single flowline is in selective communicationwith the first and the second header at a second respective end.
 32. Thearrangement of claim 31, characterized in that the flowline is coupledto the first and second headers via a three way valve.
 33. Thearrangement of claim 31 or 32, characterized in that a charge pump is incommunication with the first header.
 34. The arrangement of claims 31,32 or 33, characterized in that the single flowline is integrated into aservice umbilical together with electrical power cables.
 35. Anarrangement for controlling a downhole separator, for separatinghydrocarbons and water, comprising a manifold having a first and asecond header and isolating valves for isolating the first or the secondheader from the respective wells, at least the first header being inselective fluid communication, via a respective adjustable valve and arespective x-mas tree, with respective hydrocarbon transporting lines inthe wells, for transportation of hydrocarbons, at least one of the wellshaving a downhole separator for separating hydrocarbons and water and adownhole turbine/pump hydraulic converter for pumping separated water,characterized in that the second header is in communication with a powerfluid supply, and via a power fluid adjustable valve in furthercommunication with a turbine in the downhole turbine/pump hydraulicconverter.
 36. The arrangement of claim 35, characterized in that acharge pump is coupled to the second header, for pressurizing the powerfluid.
 37. The method of any of the claims 3-8, characterized in thatthe power fluid is used to drive a turbine in a turbine/pump hydraulicconverter for boosting the pressure of the production fluid or the wellfluid.
 38. The method of claim 37, characterized in that the power fluidis used to drive a first turbine in a turbine/pump hydraulic converterfor pumping separated seawater and also for driving a second turbine ina turbine/pump converter for boosting the pressure of the productionfluid and that the first and second turbines are controlled by dedicatedsubsea adjustable valves.
 39. The method of claim 37, characterized inthat the power fluid is used to drive a first turbine in a turbine/pumphydraulic converter for pumping separated seawater and also for drivinga second turbine in a turbine/pump converter for boosting the pressureof the production fluid and that the second turbine is controlled by adownhole adjustable valve or fixed restriction.
 40. A subsea petroleumproduction arrangement for producing hydrocarbons from a plurality ofwells, comprising a manifold having a first and a second header andisolating valves for isolating the first or the second header from therespective wells, at least the first header being in selective fluidcommunication, via a respective adjustable valve and a respective x-mastree, with respective hydrocarbon transporting lines in the wells, fortransportation of hydrocarbons, at least one of the wells having adownhole turbine/pump hydraulic converter, characterized in that thesecond header is in communication with a power fluid supply, and via apower fluid adjustable valve in further communication with a turbine inthe downhole turbine/pump hydraulic converter and that the pump of theturbine/pump hydraulic converter is pumping well fluid or productionfluid.
 41. The arrangement of any of the claims 9-27 and claim 40,characterized in that a respective dedicated subsea adjustable valve isprovided in the power fluid line for the turbine of the turbine/pumpconverter pumping well fluid or production fluid and the turbine of theturbine/pump converter pumping separated water.
 42. The arrangement ofany of the claims 9-27 and claim 40, characterized in that a downholeadjustable valve or fixed restriction is provided in the power fluidline for the turbine of the turbine/pump converter pumping well fluid orproduction fluid.
 43. A method for providing downhole three phaseseparation, characterized in that at least a part of the gas in a wellfluid is extracted from the wellfluid in a downhole gas-liquid separatorand transported in a separate line passed a downstream liquid-liquidseparator.
 44. The method of claim 43, characterized in that the gaswhich is separated from the well fluid is lead through a pipeline to aelevated centrifugal scrubber, the gas is polished, the extracted liquidbeing drained by gravity through a line into the liquid-liquidseparator, or upstream of this separator, the gas from the scrubberbeing injected into the liquid production line or transported separatelyto the seabed.
 45. A subsea petroleum production arrangement forproducing hydrocarbons, characterized in that the arrangement furthercomprising a downhole gas-liquid separator for separating at leastpartly gas from the well fluid, the separator being in communicationwith a gas line extending passed a liquid-liquid separator.
 46. A subseapetroleum production arrangement for producing hydrocarbons,characterized in that the arrangement further comprising a downholegas-liquid separator placed in a substantially horizontal section of thewell, for separating at least partly gas from the well fluid, theseparator being in communication with a gas line communication with agas scrubber at an elevated position in a vertical or deviated sectionof the well.
 47. A subsea petroleum production arrangement for producinghydrocarbons from a plurality of wells, comprising a manifold having afirst and a second header and isolating valves for isolating the firstor the second header from the respective wells, at least the firstheader being in selective fluid communication, via a respectiveadjustable valve and a respective x-mas tree, with respectivehydrocarbon transporting lines in the wells, for transportation ofhydrocarbons, and the first header being in communication with a firstflowline, the second header being in communication with a secondflowline, characterized in that the arrangement further comprising athird header, the third header being in communication with the secondflowline, for supply of gas from the second flowline to the thirdheader, for artificial lift of production fluid.
 48. The arrangement ofclaim 47, characterized in that the first header is in communicationwith an inlet side of a gas-liquid separator, the third header is via agas compressor in communication with a gas outlet side of the gas-liquidseparator, and the first flowline is in communication with the liquidoutlet of the gas-liquid separator.
 49. The arrangement of claim 47,characterized in that the first or the second flowline is incommunication with the gas outlet of the separator, to transport surplusgas to a ho
 50. The arrangement of claim 48, characterized in that thefirst or the second flowline is in communication with the gas outlet ofthe separator, to transport surplus gas to a host.